Method of using hydraulic activation chambers for anchoring downhole equipment

ABSTRACT

Provided, in one aspect, is an anchor for use with a downhole tool in a wellbore, a well system, and a method for anchoring a downhole tool within a wellbore. The anchor, according to this aspect, may include a base pipe, and two or more hydraulic activation chambers disposed radially about the base pipe, the two or more hydraulic activation chambers configured to move from a first collapsed state to a second activated state to engage with a wall of a wellbore and laterally and rotationally fix a downhole tool coupled to the base pipe within the wellbore.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional Application Ser.No. 63/086,912, filed on Oct. 2, 2020, entitled “METHOD OF USING EHSTECHNOLOGY FOR ANCHORING DOWNHOLE EQUIPMENT,” commonly assigned withthis application and incorporated herein by reference in its entirety.

BACKGROUND

The unconventional market is very competitive. The market is trendingtowards longer horizontal wells to increase reservoir contact.Multilateral wells offer an alternative approach to maximize reservoircontact. Multilateral wells include one or more lateral wellboresextending from a main wellbore. A lateral wellbore is a wellbore that isdiverted from the main wellbore or another lateral wellbore.

The lateral wellbores are typically formed by positioning one or moredeflector assemblies at desired locations in the main wellbore (e.g., anopen hole section or cased hole section) with a running tool. Thedeflector assemblies are often laterally and rotationally fixed withinthe main wellbore using a wellbore anchor.

BRIEF DESCRIPTION

Reference is now made to the following descriptions taken in conjunctionwith the accompanying drawings, in which:

FIG. 1 illustrates a schematic view of a well system designed,manufactured and operated according to one or more embodiments disclosedherein;

FIGS. 2A and 2B illustrate one embodiment of an anchor designed andmanufactured according to one or more embodiments of the disclosure;

FIGS. 3A through 5B illustrate various different views of an anchordesigned, manufactured and operated according to one or more embodimentsof the disclosure at different operational states;

FIGS. 6 through 18 illustrate cross-sectional views of a multilateralwell designed, manufactured and operated according to one or moreembodiments of the disclosure;

FIG. 19 illustrates a cross-sectional view of a multilateral welldesigned, manufactured and operated according to one or more alternativeembodiments of the disclosure; and

FIG. 20 illustrate a high-level reservoir architecture according to oneor more embodiments of the disclosure.

DETAILED DESCRIPTION

In the drawings and descriptions that follow, like parts are typicallymarked throughout the specification and drawings with the same referencenumerals, respectively. The drawn figures are not necessarily to scale.Certain features of the disclosure may be shown exaggerated in scale orin somewhat schematic form and some details of certain elements may notbe shown in the interest of clarity and conciseness. The presentdisclosure may be implemented in embodiments of different forms.

Specific embodiments are described in detail and are shown in thedrawings, with the understanding that the present disclosure is to beconsidered an exemplification of the principles of the disclosure, andis not intended to limit the disclosure to that illustrated anddescribed herein. It is to be fully recognized that the differentteachings of the embodiments discussed herein may be employed separatelyor in any suitable combination to produce desired results.

Unless otherwise specified, use of the terms “connect,” “engage,”“couple,” “attach,” or any other like term describing an interactionbetween elements is not meant to limit the interaction to directinteraction between the elements and may also include indirectinteraction between the elements described. Unless otherwise specified,use of the terms “up,” “upper,” “upward,” “uphole,” “upstream,” or otherlike terms shall be construed as generally away from the bottom,terminal end of a well; likewise, use of the terms “down,” “lower,”“downward,” “downhole,” or other like terms shall be construed asgenerally toward the bottom, terminal end of a well, regardless of thewellbore orientation. Use of any one or more of the foregoing termsshall not be construed as denoting positions along a perfectly verticalaxis. Unless otherwise specified, use of the term “subterraneanformation” shall be construed as encompassing both areas below exposedearth and areas below earth covered by water such as ocean or freshwater.

The disclosure describes a new method for anchoring equipment in awellbore. The deflector assembly is used to start a second hole sectionfrom the first section, consequently creating an open hole junction atthe deflector assembly. The term “open hole”, as used herein, means thatat least that section of the wellbore includes no casing, therebyexposing the subterranean formation. The junction may be later completedwith a pressure tight TAML (Technology Advancements of Multi-Laterals)level 5 junction. In certain situations, no cement surrounds themultilateral junction, but in other situations, cement may surround atleast a portion of the multilateral junction. In one or moreembodiments, both the open hole wellbore anchor and the open holedeflector assembly can be produced there through.

Open hole wellbore anchors do exist in the marketplace, but usuallyfeature an anchoring mechanism that spans a relatively short distance orwith a setting range limiting the application to wellbores with littlevariance in internal diameter (ID). A wellbore anchor designed accordingto the present disclosure may have a setting range of 15% or more of therun-in-hole diameter. For example, if the wellbore anchor were to have adiameter (x) when run in hole, the expanded diameter (x′) could be 1.15×or more (e.g., 8.5″ to 10″ or more). Washed out/caved in areas or unevenID in general is often seen when surveying a drilled section and findinga suitable location/depth for an open hole anchor can thus be difficult.Furthermore, the traditional open hole wellbore anchor relies on acertain formation strength of the rock in order to hold the requiredaxial and torsional loads.

There are no other open hole wellbore anchors that offer the samewellbore contact (contact area) or setting range as envisaged with thedisclosed wellbore anchor. The contact area is believed to providesuperior axial and torsional ratings. Since the disclosed wellboreanchor, in at least one embodiment, is activated by pressurized fluid intwo or more separate chambers that spans several meters or more acrossthe length of the anchor, it is believed to conform to anyirregularities in the wellbore and is thus less sensitive to an eveninternal diameter (ID) in the setting area. Furthermore, by design thedisclosed wellbore anchor will help supporting and stabilizing theformation by exerting pressure against the wellbore ID, thereby makingit less sensitive to weaker formations compared to a mechanical anchor,which to a larger degree relies on a competent formation. A wellboreanchor according to the present disclosure provides the ability to havecommunication from tubing to annulus, if required, even after being set,which is not known in the art. This feature offers the ability toperform circulation of fluid and/or a return path for pumping cementoperation.

An alternative setting method could be to have a tail pipe below therunning tool, which straddles the setting ports/valve assembly of thewellbore anchor. It is envisioned that an elastomeric element could beadded to an alternate wellbore anchor design if an annular seal would berequired.

The proposed method may prove useful in applications where equipmentsuch as a whipstock needs to be run through a restriction and anchoredin a larger ID below the restriction (e.g., through-tubing applications,where a new lateral is drilled from an existing production tubing).Downhole equipment is required to pass through upper completionrestrictions and set in the tubing ID deeper in the well.

FIG. 1 is a schematic view of a well system 100 designed, manufacturedand operated according to one or more embodiments disclosed herein. Thewell system 100 includes a platform 120 positioned over a subterraneanformation 110 located below the earth's surface 115. The platform 120,in at least one embodiment, has a hoisting apparatus 125 and a derrick130 for raising and lowering one or more downhole tools including pipestrings, such as a drill string 140. Although a land-based oil and gasplatform 120 is illustrated in FIG. 1, the scope of this disclosure isnot thereby limited, and thus could potentially apply to offshoreapplications. The teachings of this disclosure may also be applied toother land-based well systems different from that illustrated.

As shown, a main wellbore 150 has been drilled through the various earthstrata, including the subterranean formation 110. The term “main”wellbore is used herein to designate a wellbore from which anotherwellbore is drilled. It is to be noted, however, that a main wellbore150 does not necessarily extend directly to the earth's surface, butcould instead be a branch of yet another wellbore. A casing string 160may be at least partially cemented within the main wellbore 150. Theterm “casing” is used herein to designate a tubular string used to linea wellbore. Casing may actually be of the type known to those skilled inthe art as a “liner” and may be made of any material, such as steel orcomposite material and may be segmented or continuous, such as coiledtubing. The term “lateral” wellbore is used herein to designate awellbore that is drilled outwardly from its intersection with anotherwellbore, such as a main wellbore. Moreover, a lateral wellbore may haveanother lateral wellbore drilled outwardly therefrom.

A whipstock 170 according to one or more embodiments of the presentdisclosure may be positioned at a location in the main wellbore 150.Specifically, the whipstock 170 could be placed at a location in themain wellbore 150 where it is desirable for a lateral wellbore 180 toexit. Accordingly, the whipstock 170 may be used to support a millingtool used to penetrate a window in the main wellbore 150, and once thewindow has been milled and a lateral wellbore 180 formed, in someembodiments, the whipstock 170 may be retrieved and returned uphole by aretrieval tool, in some embodiments in only a single trip.

In some embodiments, an anchor 190 may be placed downhole in thewellbore 150 to support and anchor downhole tools, such as the whipstock170, for maintaining the whipstock 170 in place while drilling thelateral wellbore 180. The anchor 190, in accordance with the disclosure,may be employed in an open-hole section of the main wellbore 150, oralternatively in cased section of the main wellbore 150. As such, theanchor 190 may be configured to resist at least 6,750 newton meters (Nm)(e.g., about 5,000 lb-ft) of torque. In yet another embodiment, theanchor 190 may be configured to resist at least 13,500 newton meters(Nm) (e.g., about 10,000 lb-ft) of torque, and in yet another embodimentconfigured to resist at least 20,250 newton meters (Nm) (e.g., about15,000 lb-ft) of torque. Similarly, the anchor 190 may be configured toresist at least 1814 kg (e.g., about 4,000 lb) of axial force. In yetanother embodiment, the anchor 190 may be configured to resist at least4536 kg (e.g., about 10,000 lb) of axial force, and in yet anotherembodiment the anchor 190 may be configured to resist at least 6804 kg(e.g., about 15,000 lb) of axial force. The anchor 190 may include, insome aspects, a base pipe and two or more activation chambers disposedradially about the base pipe. The two or more activation chambers may beconfigured to move from a first collapsed state while running in hole,to a second activated state once the anchor 190 is positioned within themain wellbore 150.

In some embodiments, the anchor 190 may be hydraulically activated. Oncethe anchor 190 reaches a desired location in the main wellbore 150,fluid pressure may be applied to the two or more hydraulic activationchambers to move the two or more hydraulic activation chambers from thefirst collapsed state to the second activated state and engage a wall ofthe main wellbore 150. The anchor 190 may also include, in someembodiments, an expandable medium positioned radially about the two ormore hydraulic activation chambers. In some aspects, the expandablemedium may be configured to grip and engage the wall of the mainwellbore 150 when the two or more hydraulic activation chambers are inthe second activated state.

In at least one embodiment, the resulting main wellbore 150 has a mainwellbore open hole section, and the resulting lateral wellbore 180 has alateral wellbore open hole section. Further to this embodiment, the mainwellbore 150 may have a main wellbore completion located therein, andthe lateral wellbore 180 may have a lateral wellbore completion locatedtherein. Accordingly, in at least one embodiment, a multilateraljunction may be positioned at an intersection between the main wellboreopen hole section of the main wellbore 150 and the lateral wellbore openhole section of the lateral wellbore 150. In accordance with oneembodiment, the multilateral junction might include a main bore legforming a first pressure tight seal with the main bore completion and alateral bore leg forming a second pressure tight seal with the lateralbore completion such that the main bore completion and the lateral borecompletion are hydraulically isolated from one another. What results, inone or more embodiments, is an open hole TAML Level 5 pressure tightjunction.

Turning now to FIGS. 2A and 2B, illustrated is one embodiment of ananchor 200 designed and manufactured according to one or moreembodiments of the disclosure. FIG. 2A illustrates the anchor 200 in thecollapsed state, whereas FIG. 2B illustrates the anchor 200 in theactivated state. The anchor 200, in one embodiment, may include a basepipe 210. The base pipe 210, in at least on embodiment, is a metal basepipe. Nevertheless, other embodiments exist wherein a non-metal basepipe 210 is used.

In the embodiment of FIGS. 2A ad 2B, the base pipe 210 does not includeopenings connecting the interior of the base pipe 210 with the exteriorof the base pipe 210. However, in yet other embodiments, a plurality ofopenings may exist between the interior of the base pipe 210 and theexterior of the base pipe 210. For example, a first plurality ofopenings could be used to provide fluid communication between the basepipe 210 and the two or more hydraulic activation chambers to move thetwo or more hydraulic activation chambers from the first collapsed stateto the second activated state. In yet another embodiment, a secondplurality of openings could be used to provide fluid communicationbetween the base pipe 210 and an annulus surrounding the base pipe 210when the two or more hydraulic activation chambers are in the secondactivated state.

While not shown in FIGS. 2A and 2B, in certain embodiments, the anchor200 may include a valve coupled to the base pipe 210. In at least oneembodiment, the valve has a first setting that closes fluidcommunication to the first plurality of openings and the secondplurality of openings, a second setting that only opens fluidcommunication to the first plurality of openings, and a third settingthat only opens fluid communication to the second plurality of openings.

Two or more hydraulic activation chambers 220 may be positioned radiallyabout the base pipe 210. In some embodiments, the two or more hydraulicactivation chambers 220 may be generally linearly aligned with oneanother. As used herein, generally linearly aligned may mean the two ormore hydraulic activation chambers 220 may be linearly aligned within 10percent of their length. In other embodiments, the two or more hydraulicactivation chambers 220 may be substantially linearly aligned with eachother, wherein the two or more two or more hydraulic activation chambers220 may be linearly aligned within 5 percent of their length. In stillother embodiments, the two or more hydraulic activation chambers 220 maybe ideally linearly aligned, wherein the two or more two or morehydraulic activation chambers 220 may be linearly aligned within 1percent of their length.

In other embodiments, the two or more hydraulic activation chambers 220may be generally angularly aligned, substantially angularly aligned, orideally angularly aligned with one another. The term “generallyangularly aligned” as used herein, means that the two or more hydraulicactivation chambers 220 are within 10 degrees of parallel with oneanother. The term “substantially angularly aligned” as used herein,means that the two or more hydraulic activation chambers 220 are within5 degrees of parallel with one another. The term “ideally angularlyaligned” as used herein, means that the two or more hydraulic activationchambers 220 are within 2 degrees of parallel with one another.

The two or more hydraulic activation chambers 220 may be configured tomove from the first collapsed state shown in FIG. 2A to the secondactivated state shown in FIG. 2B to engage a wall of a wellbore. In someembodiments, when in the second activated state, the two or morehydraulic activation chambers 220 may be operable to handle at least20.7 Bar (about 300 psi) of internal pressure in the second activatedstate to engage the wall of a wellbore. In some embodiments, when in thesecond activated state, the two or more hydraulic activation chambers220 may be operable to handle at least 27.6 Bar (about 400 psi) ofinternal pressure in the second activated state to engage the wall of awellbore. In some embodiments, when in the second activated state, thetwo or more hydraulic activation chambers 220 may be operable to handleat least 51.7 Bar (about 750 psi) of internal pressure in the secondactivated state to engage the wall of a wellbore. In some alternativeembodiments, when in the second activated state, the two or morehydraulic activation chambers 220 may be operable to handle at least 68Bar (about 1000 psi) of internal pressure in the second activated stateto engage the wall of a wellbore.

In some embodiments, the anchor 200 may include an expandable medium230, which may be positioned radially about the two or more hydraulicactivation chambers 220. In certain embodiments, the expandable medium230 may be configured to split apart or deform as the two or morehydraulic activation chambers 220 expand into the second activated statesuch that the expandable medium 230 may thereafter engage and dig intothe wall of the wellbore. In at least one embodiment, the expandablemedium 230 is an exterior sleeve. In at least one other embodiment, theexpandable medium 230 is a non-filter medium, and thus does not functionto filter sand or other similar particulate matter.

The expandable medium 230 may include openings 235 therein. The openings235, in certain embodiments, allow for the expandable medium 230 toeasily expand. The general size and shape of the openings 235 may varygreatly and remain within the scope of the disclosure. In at least oneembodiment, the openings 235 are larger than the opening in a typicalsand screen. For example, the openings 235 might have a mesh value of atleast about 36 (e.g., 485 μm) or greater. In yet another embodiment, theopenings 235 might have a mesh value of at least about 20 (e.g., 850 μm)or greater, or in yet another embodiment the openings 235 might have amesh value of at least about 10 (e.g., 2,000 μm) or greater.

The expandable medium 230, in certain other embodiments, may include atextured surface on an outer surface thereof for engaging the wall ofthe wellbore. In certain instances, the textured surface has a pluralityof undulations, crenellations, corrugations, ridges, depressions, orother surface variations where the radial amplitude of the surfacevariation is at least about 1 mm (e.g., about 0.04 inches). In yetanother embodiment, the radial amplitude of the surface variation is atleast about 1.25 mm (e.g., about 0.05 inches), and in yet anotherembodiment the radial amplitude of the surface variation is betweenabout 1.25 mm (e.g., about 0.06 inches) and about 25 mm (e.g., about 1.0inches). Any known or hereafter discovered method for creating thetextured surface is within the scope of the disclosure. The expandablemedium 230 may comprise metals, carbide, polymers, and other materialsused in downhole tool applications.

In some embodiments, an elastomeric element 237 may be positioned aboutthe two or more hydraulic activation chambers 220, whether directlyabout the two or more hydraulic activation chambers 220, about theexpandable medium 230, or form all or part of the expandable medium 230.In yet another embodiment, the elastomeric element 237 is an annularelastomeric element configured as an annular seal. The elastomericelement 237 (e.g., swellable elastomer in some embodiments) may beactivated by temperature alone, fluid existing in the wellbore,completion fluid inserted into the wellbore, or any combination of theabove. In an alternative embodiment, the elastomeric element 237 may beactivated by a dedicated well treatment run to pump activation fluid tothe elastomeric element 237.

In certain embodiments, two or more bridging plates 240 may bepositioned radially about the two or more hydraulic activation chambers220. The two or more bridging plates 240 may be configured to extendacross at least a gap between outer portions of the two or morehydraulic activation chambers 220 when the two or more hydraulicactivation chambers 220 are in the second activated state as shown inFIG. 2B. The two or more bridging plates 240 may be configured, in someaspects, to provide support for the expandable medium 230 positionedabout the two or more hydraulic activation chambers 220. While it isillustrated that the two or more bridging plates 240 include openingstherein, other embodiments may exist wherein the two or more bridgingplates 240 do not include openings therein. Although not shown in theillustrated embodiment, certain embodiments of the two or more bridgingplates 240 may include protrusions or a textured surface which mayengage the wall of the wellbore, and in some embodiments, theprotrusions may extend through the openings 235 in the expandable medium230.

While the embodiment of FIGS. 2A and 2B illustrate the existence of theexpandable medium 230 and the two or more bridging plates 240, otherembodiments exist wherein the two or more hydraulic activation chambers220 are fixed to the base pipe 210. In such an embodiment, the two ormore hydraulic activation chambers 220 are unencumbered, and thus mayengage directly with the wellbore when in the second activated stateillustrated in FIG. 2B.

Turning to FIGS. 3A through 5B, illustrated are various different viewsof an anchor 300 designed, manufactured and operated according to one ormore embodiments of the disclosure at different operational states.FIGS. 3A and 3B illustrate a partial sectional view and across-sectional view, respectively, of the anchor 300 at a run-in holestate, FIGS. 4A and 4B illustrate a partial sectional view and across-sectional view, respectively, of the anchor 300 when a firstplurality of opening are in fluid communication with the two or morehydraulic activation chambers, and FIGS. 5A and 5B illustrate a partialsectional view and a cross-sectional view, respectively, of the anchor300 when a second plurality of opening are in fluid communication withan annulus surrounding the base pipe.

The anchor 300 illustrated in FIGS. 3A through 5B initially includes abase pipe 310, and two or more hydraulic activation chambers 320 (e.g.,at least four hydraulic activation chambers in one embodiment) disposedradially about the base pipe 310, the two or more hydraulic activationchambers 320 configured to move from a first collapsed state (e.g., asshown in FIGS. 3A and 3B) to a second activated state (e.g., as shown inFIGS. 4A through 5B) to engage with a wall of a wellbore and laterallyand rotationally fix a downhole tool coupled to the base pipe 310 withinthe wellbore. In the illustrated embodiment, the base pipe 310 has alength (l_(bp)) at least 10 times a diameter (d) of the base pipe 310,and the two or more hydraulic activation chambers extending along atleast a portion of the length (l_(bp)). In yet another embodiment, thelength (l_(bp)) of the base pipe 310 is at least 2 meters long and alength (l_(ac)) of the two or more hydraulic activation chambers 320 isat least 1.5 meters long. In at least one other embodiment, the length(l_(bp)) of the base pipe 310 is at least 4 meters long and the length(l_(ac)) of the two or more hydraulic activation chambers 320 is atleast 3 meters long. In yet another embodiment, the length (l_(bp)) ofthe base pipe 310 is at least 10 meters long and the length (l_(ac)) ofthe two or more hydraulic activation chambers 320 is at least 7.5 meterslong.

The base pipe 310, in at least one embodiment, includes a firstplurality of openings 312, the first plurality of openings 312configured to provide fluid communication between the base pipe 310 andthe two or more hydraulic activation chambers 320 to move the two ormore hydraulic activation chambers 320 from the first collapsed state(e.g., shown in FIGS. 3A and 3B) to the second activated state (e.g.,shown in FIGS. 4A through h5B). The base pipe, in at least one otherembodiment, includes a second plurality of openings 314, the secondplurality of openings 314 configured to provide fluid communicationbetween the base pipe 310 and an annulus 316 surrounding the base pipe310 when the two or more hydraulic activation chambers 320 are in thesecond activated state.

In the illustrated embodiment of FIGS. 3A through 5B, the anchor 300additionally includes a valve 318 coupled to the base pipe 310. Thevalve 318, in one or more embodiments, includes a first setting thatcloses fluid communication to the first plurality of openings 312 andthe second plurality of openings 314, a second setting that only opensfluid communication to the first plurality of openings 312, and a thirdsetting that only opens fluid communication to the second plurality ofopenings 314. While the valve 318 has been illustrated as a slidingsleeve valve in FIGS. 3A through 5B, other types of valves may be usedand remain within the scope of the disclosure.

With reference to FIGS. 3A and 3B, the valve 318 is at the firstsetting, wherein fluid communication to the first plurality of openings312 and the second plurality of openings 314 is closed, and thus fluid350 may bypass the anchor 300. Accordingly, the two or more hydraulicactivation chambers 320 remain in the first collapsed state.

With reference to FIGS. 4A and 4B, the valve 318 is at the secondsetting, wherein fluid communication is only open to the first pluralityof openings 312. Accordingly, fluid 360 may enter the two or morehydraulic activation chambers 320 and move them to the second activatedstate. In at least one embodiment, the fluid 360 plastically deforms thetwo or more hydraulic activation chambers 320, such that they may remainin the second activated state regardless of the setting of the valve318. In yet another embodiment, the valve 318 moves from the secondstate to either of the first state or the third state while the two ormore hydraulic activation chambers 320 are under pressure. Accordingly,the pressurized fluid 360 may be trapped within the two or morehydraulic activation chambers 320, thereby keeping them in the secondactivated state.

With reference to FIGS. 5A and 5B, the valve 318 is at the thirdsetting, wherein fluid communication is only open to the secondplurality of openings 314. Accordingly, fluid 370 may move between thebase pipe 310 and the annulus 316 surrounding the base pipe 310 when thetwo or more hydraulic activation chambers 320 are in the secondactivated state.

Turning now to FIGS. 6 through 18, illustrated are cross-sectional viewsof a multilateral well 600 designed, manufactured and operated accordingto one or more embodiments of the disclosure. The multilateral well 600illustrated in the embodiment of FIG. 6 includes a larger uphole casingsection 610 and a smaller downhole casing section 620. The multilateralwell 600 additionally includes an open hole main wellbore 630. Forexample, in the illustrated embodiment of FIG. 6, a drilling assembly640 including a drill bit 650 is being deployed within the multilateralwell 600 to form the main wellbore 630.

Turning to FIG. 7, illustrated is the multilateral well 600 of FIG. 6after positioning a downhole tool 700 within the main wellbore 630 usinga downhole conveyance 780. The downhole tool 700, in one or moreembodiments, includes a main bore completion 710 (e.g., including a sandscreen 712 and one or more main bore completion sealing elements 714).The downhole tool 700 additionally includes an anchor 720. The anchor720, in one or more embodiments, may be similar to one or more of theanchors discussed above with regard to FIGS. 1 through 5B. Accordingly,the anchor 720 may include a base pipe, and two or more hydraulicactivation chambers disposed radially about the base pipe, the two ormore hydraulic activation chambers configured to move from a firstcollapsed state to a second activated state to engage with a wall of awellbore (e.g., main wellbore 630) and laterally and rotationally fixthe downhole tool 700 therein. In the illustrated embodiment, the anchor720 is coupled uphole of the main bore completion 710, and is in theradially retracted state.

The downhole tool 700 may additionally include an anchor setting tool730. The anchor setting tool 730, in one or more embodiments, mayinclude a check valve, shearable ball-seat, flapper valve, rupture discor similar device for setting the anchor 720. The downhole tool mayadditionally include a whipstock 740 (e.g., an open hole whipstock withpre-installed running tool) having a through bore extending entirelytherethrough. The whipstock 740, as those skilled in the art appreciate,may be used (e.g., along with a drill bit) to drill a lateral wellboreoff of the main wellbore 630. In at least one embodiment, the downholetool 700 additionally includes a swivel 750. The swivel 750, in one ormore embodiments, allows for the orientation of the whipstock 740without turning the entire main bore completion 710.

The downhole conveyance 780 illustrated in FIG. 7 includes a circulationsub 785, as well as a work-string orientation tool (WOT) or measuringwhile drilling tool (MWD) 790. The WOT or MWD 790 may be used to enablea tool face reading of the whipstock 740 for orientation purposes.

Turning to FIG. 8, illustrated is the multilateral well 600 of FIG. 7after orienting the whipstock 740. For example, when at depth, fluidcould flow through the circulation sub 785 to obtain a whipstock 740tool face orientation. In at least one embodiment, such as that shown,the whipstock 740 is oriented to a high side of the main wellbore 630.Nevertheless, other orientations are within the scope of the disclosure

Turning to FIG. 9, illustrated is the multilateral well 600 of FIG. 8after activating/deploying the anchor 720. The anchor 720 may beactivated/deployed by first setting its valve to its second position,and then pressuring up on the two or more hydraulic activation chambersto move the two or more hydraulic activation chambers from their firstcollapsed state to their second activated state. In at least oneembodiment, a pre-determined activation pressure is maintained for aperiod of time to fully activate the anchor 720.

In at least one embodiment, an optional push/pull test may be performedon the anchor 720 to confirm that it is fully activated. Thereafter,pressure may be applied to the downhole conveyance 780 to release itfrom the whipstock 740. Thereafter, the downhole conveyance 780 may bepulled out of the main wellbore 630.

Turning to FIG. 10, illustrated is the multilateral well 600 of FIG. 9after deploying a drilling assembly 1040 including a drill bit 1050within the multilateral well 600 to form a lateral rat hole 1030. Thelateral rat hole 1030 is formed, in at least one embodiment, bydeflecting the drill bit 1050 off of the whipstock 740. The lateral rathole 1030, in at least one embodiment, is a pocket run in the formationto ensure successful sidetrack/departure in an open hole scenario.

Turning to FIG. 11, illustrated is the multilateral well 600 of FIG. 10after deploying the drilling assembly 1040 including the drill bit 1050(or an alternative drilling assembly including an alternative drill bit)to complete a lateral wellbore 1130 within the multilateral well 600.The lateral wellbore 1130 may be drilled to depth as planned. In one ormore embodiments, the lateral wellbore 1130 may extend up to 10,000meters from the main wellbore 630. As shown in FIG. 11, the mainwellbore 630 includes a main wellbore open hole section 1150, and thelateral wellbore 1130 includes a lateral wellbore open hole section1160.

Turning to FIG. 12, illustrated is the multilateral well 600 of FIG. 11after positioning a downhole tool 1200 within the lateral wellbore 1130using a downhole conveyance 1280. The downhole tool 1200, in one or moreembodiments, includes a lateral bore completion 1210 (e.g., including asand screen 1212 and one or more main bore completion sealing elements1214). The downhole tool 1200 may additionally include an anchor 1220.The anchor 1220, in one or more embodiments, may be similar to one ormore of the anchors discussed above with regard to FIGS. 1 through 5B.Accordingly, the anchor 1220 may include a base pipe, and two or morehydraulic activation chambers disposed radially about the base pipe, thetwo or more hydraulic activation chambers configured to move from afirst collapsed state to a second activated state to engage with a wallof a wellbore (e.g., lateral wellbore 1130) and laterally androtationally fix the downhole tool 1200 therein. In the illustratedembodiment, the anchor 1220 is coupled uphole of the lateral borecompletion 1210, and is in the radially retracted state.

Turning to FIG. 13, illustrated is the multilateral well 600 of FIG. 12after activating/deploying the anchor 1220. The anchor 1220 may beactivated/deployed by first setting its valve to its second position,and then pressuring up on the two or more hydraulic activation chambersto move the two or more hydraulic activation chambers from their firstcollapsed state to their second activated state. In at least oneembodiment, a pre-determined activation pressure is maintained for aperiod of time to fully activate the anchor 1220.

Turning to FIG. 14, illustrated is the multilateral well 600 of FIG. 13after employing a downhole conveyance 1480 to wash down and clean outthe whipstock 740 bore. In at least one embodiment, the downholeconveyance 1480 is the same downhole conveyance as used to position thedownhole tool 1200 within the lateral wellbore 1130. In otherembodiments, however, they are different tools.

Turning to FIG. 15, illustrated is the multilateral well 600 of FIG. 14after positioning a multilateral junction 1500 at an intersectionbetween the main wellbore open hole section 1150 and the lateralwellbore open hole section 1160. The multilateral junction 1500, in theillustrated embodiment, includes a main bore leg 1510 for engaging withthe main bore completion 710 (e.g., by stabbing into the whipstock 740in one embodiment) and a lateral bore leg 1515 for engaging with thelateral bore completion 1210.

Coupled uphole of the multilateral junction 1500, in one or moreembodiments, is another anchor 1520. The anchor 1520, in one or moreembodiments, may be similar to one or more of the anchors discussedabove with regard to FIGS. 1 through 5B. Accordingly, the anchor 1520may include a base pipe, and two or more hydraulic activation chambersdisposed radially about the base pipe, the two or more hydraulicactivation chambers configured to move from a first collapsed state to asecond activated state to engage with a wall of a wellbore (e.g., mainwellbore 630) and laterally and rotationally fix the multilateraljunction 1500 therein. In the illustrated embodiment, the anchor 1520 iscoupled uphole of the multilateral junction 1500, and is in the radiallyretracted state.

Turning to FIG. 16, illustrated is the multilateral well 600 of FIG. 15after activating/deploying the anchor 1520. The anchor 1520 may beactivated/deployed by first setting its valve to its second position,and then pressuring up on the two or more hydraulic activation chambersto move the two or more hydraulic activation chambers from their firstcollapsed state to their second activated state. In at least oneembodiment, a pre-determined activation pressure is maintained for aperiod of time to fully activate the anchor 1520.

Turning to FIG. 17, illustrated is the multilateral well 600 of FIG. 16after coupling an intermediate liner 1700 to an uphole end of themultilateral junction 1500. The intermediate liner 1700, in theillustrated embodiment, includes a first set of one or more intermediateliner sealing elements 1710, a second set of one or more intermediateliner sealing elements 1730, and main wellbore screen assembly 1720positioned between the first set of sealing elements 1710 and the secondset of sealing elements 1730. In at least one embodiment, the first setof sealing elements 1710 and the second set of sealing elements 1730seal an annulus between the intermediate liner 1700 and the mainwellbore open hole section 1150.

What results in FIG. 17, is an open-hole pressure tight TAML level 5junction. For example, the multilateral junction 1500 is entirelypositioned in the main wellbore open hole section 1150 and/or thelateral wellbore open hole section 1160. Moreover, in at least oneembodiment, no cement surrounds the multilateral junction 1500, and inat least one other embodiment no cement exists in either of the mainwellbore open hole section 1150 or the lateral wellbore open holesection 1160.

Furthermore, in at least one embodiment, the main bore leg 1510 of themultilateral junction 1500 forms a first pressure tight seal with themain bore completion 710, and the lateral bore leg 1515 of themultilateral junction 1500 forms a second pressure tight seal with thelateral bore completion 1210. Additionally, in at least one embodiment,a pressure tight seal exists entirely around the multilateral junction1500, as a result of the one or more main bore completion sealingelements 714 sealing an annulus between the main bore completion 710 andthe main wellbore open hole section 1150, the one or more lateral borecompletion sealing elements 1214 sealing an annulus between the lateralbore completion 1210 and the lateral wellbore open hole section 1160,and the one or more intermediate liner sealing elements 1710, 1730sealing an annulus between the intermediate liner 1700 and the mainwellbore open hole section 1150.

Turning to FIG. 18, illustrated is the multilateral well 600 of FIG. 17after positioning intelligent completion components within the mainwellbore 630. FIG. 18 additionally illustrates the commingled flow pathsof the main bore completion 710, the lateral bore completion 1210, andthe intermediate liner 1700.

Turning now to FIG. 19, illustrated is a cross-sectional view of amultilateral well 1900 designed, manufactured and operated according toone or more alternative embodiments of the disclosure. The multilateralwell 1900 is similar in many respects to the multilateral well 600 ofFIGS. 6 through 18. Accordingly, like reference numbers have been usedto indicate similar, if not identical, features. The multilateral well1900 differs, for the most part, from the multilateral well 600, in thatthe multilateral well 1900 includes a second lateral wellbore 1910having a second lateral wellbore open hole section 1915. The secondlateral wellbore 1910, in at least one embodiment, includes a downholetool 1920 positioned therein, the downhole tool 1920 including a secondlateral bore completion 1930 (e.g., including a sand screen and one ormore main bore completion sealing elements) and an anchor 1940. Theanchor 1940, in one or more embodiments, may be similar to one or moreof the anchors discussed above with regard to FIGS. 1 through 5B. Themultilateral well 1900 additionally includes a second multilateraljunction 1950 positioned proximate an intersection between the mainwellbore 630 and a second lateral wellbore 1910. The multilateral well1900 may additionally include one or more multilateral junction sealingelements 1960 sealing an annulus between the second multilateraljunction 1950 and the main wellbore open hole section 1150.

Turning now to FIG. 20, illustrated is a high-level reservoirarchitecture 2000 according to one or more embodiments of thedisclosure. The high-level reservoir architecture 2000 illustrated inFIG. 20 depicts multiple instances of open-hole pressure tight TAMLlevel 5 junctions, for example at one or more of the twigs thereof.Furthermore, the high-level reservoir architecture illustrates that themain wellbore and the lateral wellbores may have similar open holediameters thereof.

Aspects disclosed herein include:

A. An anchor for use with a downhole tool in a wellbore, the anchorincluding: 1) a base pipe; and 2) two or more hydraulic activationchambers disposed radially about the base pipe, the two or morehydraulic activation chambers configured to move from a first collapsedstate to a second activated state to engage with a wall of a wellboreand laterally and rotationally fix a downhole tool coupled to the basepipe within the wellbore.

B. A well system, the well system including: 1) a wellbore; 2) adownhole tool positioned within the wellbore; and 3) an anchor coupledto the downhole tool and positioned within the wellbore, the anchorincluding: a) a base pipe; and b) two or more hydraulic activationchambers disposed radially about the base pipe, the two or morehydraulic activation chambers configured to move from a first collapsedstate to a second activated state to engage with a wall of the wellboreand laterally and rotationally fix the downhole tool within thewellbore.

C. A method for anchoring a downhole tool within a wellbore, the methodincluding: 1) positioning a downhole tool within a wellbore, thedownhole tool having an anchor coupled thereto, the anchor including: a)a base pipe; and b) two or more hydraulic activation chambers disposedradially about the base pipe; and 2) applying fluid pressure to the twoor more hydraulic activation chambers to move the two or more hydraulicactivation chambers from a first collapsed state to a second activatedstate to engage with a wall of the wellbore and laterally androtationally fix the downhole tool within the wellbore.

D. A well system, the well system including: 1) a main wellbore, themain wellbore having a main wellbore open hole section; 2) a lateralwellbore extending from the main wellbore, the lateral wellbore having alateral wellbore open hole section; 3) a main bore completion locatedwithin the main wellbore and a lateral bore completion located withinthe lateral wellbore; and 4) a multilateral junction positioned at anintersection between the main wellbore open hole section of the mainwellbore and the lateral wellbore open hole section of the lateralwellbore, the multilateral junction including a main bore leg forming afirst pressure tight seal with the main bore completion and a lateralbore leg forming a second pressure tight seal with the lateral borecompletion such that the main bore completion and the lateral borecompletion are hydraulically isolated from one another.

E. A method for forming a well system, the method including: 1) forminga main wellbore, the main wellbore having a main wellbore open holesection; 2) forming a lateral wellbore extending from the main wellbore,the lateral wellbore having a lateral wellbore open hole section; 3)placing a main bore completion within the main wellbore and placing alateral bore completion within the lateral wellbore; and 4) positioninga multilateral junction at an intersection between the main wellboreopen hole section of the main wellbore and the lateral wellbore openhole section of the lateral wellbore, the multilateral junctionincluding a main bore leg forming a first pressure tight seal with themain bore completion and a lateral bore leg forming a second pressuretight seal with the lateral bore completion such that the main borecompletion and the lateral bore completion are hydraulically isolatedfrom one another.

Aspects A, B, C, D and E may have one or more of the followingadditional elements in combination: Element 1: further including anexpandable medium disposed about the two or more hydraulic activationchambers, the expandable medium configured to expand radially via thetwo or more hydraulic activation chambers to fix the downhole toolwithin the wellbore. Element 2: wherein the expandable medium is anexpandable non-filter medium. Element 3: further including two or morebridging plates positioned radially about the two or more expandablechambers, wherein the two or more bridging plates are configured toextend across at least a gap between outer portions of the two or moreexpandable chambers when the two or more hydraulic activation chambersare in the second activated state. Element 4: further including aplurality of openings in the base pipe, the plurality of openingsconfigured to provide fluid communication between the base pipe and thetwo or more hydraulic activation chambers to move the two or morehydraulic activation chambers from the first collapsed state to thesecond activated state. Element 5: wherein the plurality of openings area first plurality of openings, and further including a second pluralityof openings in the base pipe, the second plurality of openingsconfigured to provide fluid communication between the base pipe and anannulus surrounding the base pipe when the two or more hydraulicactivation chambers are in the second activated state. Element 6:further including a valve coupled to the base pipe, the valve having afirst setting that closes fluid communication to the first plurality ofopenings and the second plurality of openings, a second setting thatonly opens fluid communication to the first plurality of openings, and athird setting that only opens fluid communication to the secondplurality of openings. Element 7: further including an elastomericelement positioned about the two or more hydraulic activation chambers.Element 8: wherein the elastomeric element is an annular elastomericelement configured as an annular seal. Element 9: wherein the base pipehas a length (l_(bp)) at least 10 times a diameter (d) of the base pipe,and further wherein the two or more hydraulic activation chambers extendalong at least a portion of the length (l_(bp)). Element 10: wherein thelength (l_(bp)) of the base pipe is at least 2 meters long and a length(l_(ac)) of the two or more hydraulic activation chambers is at least1.5 meters long. Element 11: wherein the length (l_(bp)) of the basepipe is at least 4 meters long and a length (l_(ac)) of the two or morehydraulic activation chambers is at least 3 meters long. Element 12:wherein the length (l_(bp)) of the base pipe is at least 10 meters longand a length (l_(ac)) of the two or more hydraulic activation chambersis at least 7.5 meters long. Element 13: wherein at least four hydraulicactivation chambers are disposed radially about the base pipe. Element14: wherein the downhole tool is a lower completion. Element 15: whereinthe lower completion includes production tubing having a screenassembly. Element 16: wherein the downhole tool is coupled to a downholeend of the anchor, and further wherein the anchor is configured tolaterally and rotationally fix the production tubing having the screenassembly within the wellbore. Element 17: wherein the wellbore is a mainwellbore, and further including a lateral wellbore extending from themain wellbore, wherein the downhole tool forms at least a portion of amultilateral junction positioned proximate an intersection between themain wellbore and the lateral wellbore. Element 18: wherein the downholetool is a whipstock, the anchor laterally and rotationally fixing thewhipstock within the wellbore. Element 19: wherein the downhole toolforms at least a portion of a first multilateral junction, the anchor isa first anchor and the lateral wellbore is a first lateral wellbore, andfurther including: a second downhole tool positioned within thewellbore; and a second anchor coupled to the second downhole tool andpositioned within the wellbore, the second anchor including; a secondbase pipe; and a second set of two or more hydraulic activation chambersdisposed radially about the second base pipe, the second set of two ormore hydraulic activation chambers configured to move from the firstcollapsed state to the second activated state to engage with the wall ofthe wellbore and laterally and rotationally fix the second downhole toolwithin the wellbore. Element 20: wherein the second downhole tool formsat least a portion of a second multilateral junction positionedproximate an intersection between the main wellbore and a second lateralwellbore. Element 21: wherein the main wellbore and the lateral wellborehave a similar open hole diameter. Element 22: wherein the whipstockincludes a through bore extending entirely there through. Element 23:further including an expandable medium disposed about the two or morehydraulic activation chambers, the expandable medium configured toexpand radially via the two or more hydraulic activation chambers to fixthe downhole tool within the wellbore. Element 24: wherein theexpandable medium is an expandable non-filter medium. Element 25:wherein the wellbore is an open hole wellbore. Element 26: furtherincluding an expandable medium disposed about the two or more hydraulicactivation chambers, the expandable medium expanding radially whenapplying the fluid pressure to the two or more hydraulic activationchambers to fix the downhole tool within the wellbore. Element 27:wherein positioning a downhole tool within a wellbore includespositioning a lower completion including production tubing having ascreen assembly within a wellbore, the applying laterally androtationally fixing the lower completion including the production tubinghaving the screen assembly within the wellbore. Element 28: wherein thewellbore is a main wellbore, and further including a lateral wellboreextending from the main wellbore, wherein positioning a downhole toolwithin a wellbore includes positioning a downhole tool forming at leasta portion of a multilateral junction proximate an intersection betweenthe main wellbore and the lateral wellbore. Element 29: furtherincluding one or more main bore completion sealing elements sealing anannulus between the main bore completion and the main wellbore open holesection. Element 30: further including one or more lateral borecompletion sealing elements sealing an annulus between the lateral borecompletion and the lateral wellbore open hole section. Element 31:further including an intermediate liner coupled with an uphole end ofthe multilateral junction, the intermediate liner including one or moreintermediate liner sealing elements sealing an annulus between theintermediate liner and the main wellbore open hole section. Element 32:wherein the one or more intermediate liner sealing elements are a firstset of one or more intermediate liner sealing elements, and furtherincluding a second set of one or more intermediate liner sealingelements sealing the annulus between the intermediate liner and the mainwellbore open hole section, the second set of one or more intermediateliner sealing elements laterally offset from the first set of one ormore intermediate liner sealing elements. Element 33: further includinga main wellbore screen assembly positioned between the first set of oneor more intermediate liner sealing elements and the second sets of oneor more intermediate liner sealing elements. Element 34: wherein nocement surrounds the multilateral junction. Element 35: wherein thelateral wellbore is a first lateral wellbore and the lateral borecompletion is a first lateral bore completion, and further including asecond lateral wellbore extending from the main wellbore, the secondlateral wellbore having a second lateral wellbore open hole section anda second lateral bore completion. Element 36: wherein the multilateraljunction is a first multilateral junction and the intersection is afirst intersection, and further including a second multilateral junctionpositioned at a second intersection between the main wellbore open holesection of the main wellbore and the second lateral wellbore open holesection of the second lateral wellbore, the second multilateral junctionincluding a second main bore leg forming a third pressure tight sealwith the first multilateral junction and a fourth lateral bore legforming a fourth pressure tight seal with the second lateral borecompletion. Element 37: further including one or more multilateraljunction sealing elements sealing an annulus between the secondmultilateral junction and the main wellbore open hole section.

Those skilled in the art to which this application relates willappreciate that other and further additions, deletions, substitutionsand modifications may be made to the described embodiments.

What is claimed is:
 1. An anchor for use with a downhole tool in awellbore, comprising: a base pipe; and two or more hydraulic activationchambers disposed radially about the base pipe, the two or morehydraulic activation chambers configured to move from a first collapsedstate to a second activated state to engage with a wall of a wellboreand laterally and rotationally fix a downhole tool coupled to the basepipe within the wellbore.
 2. The anchor as recited in claim 1, furtherincluding an expandable medium disposed about the two or more hydraulicactivation chambers, the expandable medium configured to expand radiallyvia the two or more hydraulic activation chambers to fix the downholetool within the wellbore.
 3. The anchor as recited in claim 2, whereinthe expandable medium is an expandable non-filter medium.
 4. The anchoras recited in claim 1, further including two or more bridging platespositioned radially about the two or more expandable chambers, whereinthe two or more bridging plates are configured to extend across at leasta gap between outer portions of the two or more expandable chambers whenthe two or more hydraulic activation chambers are in the secondactivated state.
 5. The anchor as recited in claim 1, further includinga plurality of openings in the base pipe, the plurality of openingsconfigured to provide fluid communication between the base pipe and thetwo or more hydraulic activation chambers to move the two or morehydraulic activation chambers from the first collapsed state to thesecond activated state.
 6. The anchor as recited in claim 5, wherein theplurality of openings are a first plurality of openings, and furtherincluding a second plurality of openings in the base pipe, the secondplurality of openings configured to provide fluid communication betweenthe base pipe and an annulus surrounding the base pipe when the two ormore hydraulic activation chambers are in the second activated state. 7.The anchor as recited in claim 6, further including a valve coupled tothe base pipe, the valve having a first setting that closes fluidcommunication to the first plurality of openings and the secondplurality of openings, a second setting that only opens fluidcommunication to the first plurality of openings, and a third settingthat only opens fluid communication to the second plurality of openings.8. The anchor as recited in claim 1, further including an elastomericelement positioned about the two or more hydraulic activation chambers.9. The anchor as recited in claim 8, wherein the elastomeric element isan annular elastomeric element configured as an annular seal.
 10. Theanchor as recited in claim 1, wherein the base pipe has a length(l_(bp)) at least 10 times a diameter (d) of the base pipe, and furtherwherein the two or more hydraulic activation chambers extend along atleast a portion of the length (l_(bp)).
 11. The anchor as recited inclaim 10, wherein the length (l_(bp)) of the base pipe is at least 2meters long and a length (l_(ac)) of the two or more hydraulicactivation chambers is at least 1.5 meters long.
 12. The anchor asrecited in claim 10, wherein the length (l_(bp)) of the base pipe is atleast 4 meters long and a length (l_(ac)) of the two or more hydraulicactivation chambers is at least 3 meters long.
 13. The anchor as recitedin claim 10, wherein the length (l_(bp)) of the base pipe is at least 10meters long and a length (l_(ac)) of the two or more hydraulicactivation chambers is at least 7.5 meters long.
 14. The anchor asrecited in claim 1, wherein at least four hydraulic activation chambersare disposed radially about the base pipe.
 15. A well system,comprising: a wellbore; a downhole tool positioned within the wellbore;and an anchor coupled to the downhole tool and positioned within thewellbore, the anchor including: a base pipe; and two or more hydraulicactivation chambers disposed radially about the base pipe, the two ormore hydraulic activation chambers configured to move from a firstcollapsed state to a second activated state to engage with a wall of thewellbore and laterally and rotationally fix the downhole tool within thewellbore.
 16. The well system as recited in claim 15, wherein thedownhole tool is a lower completion.
 17. The well system as recited inclaim 16, wherein the lower completion includes production tubing havinga screen assembly.
 18. The well system as recited in claim 17, whereinthe downhole tool is coupled to a downhole end of the anchor, andfurther wherein the anchor is configured to laterally and rotationallyfix the production tubing having the screen assembly within thewellbore.
 19. The well system as recited in claim 15, wherein thewellbore is a main wellbore, and further including a lateral wellboreextending from the main wellbore, wherein the downhole tool forms atleast a portion of a multilateral junction positioned proximate anintersection between the main wellbore and the lateral wellbore.
 20. Thewell system as recited in claim 19, wherein the downhole tool is awhipstock, the anchor laterally and rotationally fixing the whipstockwithin the wellbore.
 21. The well system as recited in claim 19, whereinthe downhole tool forms at least a portion of a first multilateraljunction, the anchor is a first anchor and the lateral wellbore is afirst lateral wellbore, and further including: a second downhole toolpositioned within the wellbore; and a second anchor coupled to thesecond downhole tool and positioned within the wellbore, the secondanchor including; a second base pipe; and a second set of two or morehydraulic activation chambers disposed radially about the second basepipe, the second set of two or more hydraulic activation chambersconfigured to move from the first collapsed state to the secondactivated state to engage with the wall of the wellbore and laterallyand rotationally fix the second downhole tool within the wellbore. 22.The well system as recited in claim 21, wherein the second downhole toolforms at least a portion of a second multilateral junction positionedproximate an intersection between the main wellbore and a second lateralwellbore.
 23. The well system as recited in claim 19, wherein the mainwellbore and the lateral wellbore have a similar open hole diameter. 24.The well system as recited in claim 19, wherein the whipstock includes athrough bore extending entirely there through.
 25. The well system asrecited in claim 15, further including an expandable medium disposedabout the two or more hydraulic activation chambers, the expandablemedium configured to expand radially via the two or more hydraulicactivation chambers to fix the downhole tool within the wellbore. 26.The well system as recited in claim 25, wherein the expandable medium isan expandable non-filter medium.
 27. The well system as recited in claim15, wherein the wellbore is an open hole wellbore.
 28. A method foranchoring a downhole tool within a wellbore, comprising: positioning adownhole tool within a wellbore, the downhole tool having an anchorcoupled thereto, the anchor including: a base pipe; and two or morehydraulic activation chambers disposed radially about the base pipe; andapplying fluid pressure to the two or more hydraulic activation chambersto move the two or more hydraulic activation chambers from a firstcollapsed state to a second activated state to engage with a wall of thewellbore and laterally and rotationally fix the downhole tool within thewellbore.
 29. The method as recited in claim 28, further including anexpandable medium disposed about the two or more hydraulic activationchambers, the expandable medium expanding radially when applying thefluid pressure to the two or more hydraulic activation chambers to fixthe downhole tool within the wellbore.
 30. The method as recited inclaim 28, wherein positioning a downhole tool within a wellbore includespositioning a lower completion including production tubing having ascreen assembly within a wellbore, the applying laterally androtationally fixing the lower completion including the production tubinghaving the screen assembly within the wellbore.
 31. The method asrecited in claim 28, wherein the wellbore is a main wellbore, andfurther including a lateral wellbore extending from the main wellbore,wherein positioning a downhole tool within a wellbore includespositioning a downhole tool forming at least a portion of a multilateraljunction proximate an intersection between the main wellbore and thelateral wellbore.